Designing and Modeling Value-Added Production Sharing Contracts (VAPSC): From Offshore Gas to LNG in Lebanon

Abstract

This article presents the value-added production-sharing contract (VAPSC), an extension of traditional production-sharing contracts (PSCs), which encompasses raw materials production, subsequent processing, and the final ‘sharing’ of goods. Developing countries often face challenges in oil and gas exploration, production, and sector development, necessitating new collaborative frameworks between governments, industries, and international companies. The study justifies the economic terms of VAPSC that align with Lebanon’s national regulations, focusing on offshore gas production and the subsequent production and sale of liquefied natural gas (LNG). The research evaluates VAPSC application in Lebanon through a case study involving offshore gas field development, LNG plant construction, and consequent LNG-sharing. Results demonstrate the VAPSC potential to promote petroleum sector development by generating added value for both the state and society, as well as economic efficiency for the contractor. The research contributes to contract theory by introducing VAPSC as a novel framework for integrating hydrocarbon extraction, subsequent processing, and value-added product distribution, offering a replicable model for other resource-rich developing nations. The main findings include the design of a new type of contract—VAPSC—along with an economic-mathematical model for optimizing government-investor partnerships and the definition of key contractual terms.

1. Introduction

The development of oil and gas fields in countries lacking the necessary equipment, technology, and skilled specialists—particularly in offshore and geologically challenging conditions—often depends on contract systems to define the obligations and rights of the involved parties, namely the government and the investor.

Established practices in selecting contract models for oil and gas projects suggest that there is no one-size-fits-all solution. All contract types are inherently complex, requiring careful justification to achieve mutual benefits and align the interests of the parties. These differences stem primarily from variations in property rights over oil and gas resources and the allocation of economic risks. A critical challenge in designing oil and gas contracts lies in the equitable distribution of wealth derived from hydrocarbon production between the government and the investors who ensure the optimal extraction of resources. The absence of an objective criterion for wealth distribution often leads to conflicts and tensions.

To establish effective economic parameters for oil and gas contracts, it is essential first to select an appropriate contract type and then define key variables such as royalties, taxes, and mechanisms for reimbursing or excluding investor costs. These factors are typically regulated by national legislation and are consistently applied to hydrocarbon exploration and development projects. Among these models, cost reimbursement (CR) contracts have been dominant. However, a recent trend, introduced by the Indonesian government in 2017, suggests a transition to gross income-sharing models, such as the Gross Split mechanism. The choice of contract form largely depends on the profitability of projects and the distribution of risks between the parties.

Emerging oil and gas producers increasingly aim to transition from mere hydrocarbon production to higher value added by producing new products, refining raw materials, and building transportation infrastructure. Achieving this requires providing attractive incentives for investors willing to participate in these processes. Consequently, production-sharing agreement models must evolve to include additional parameters that optimize outcomes for all stakeholders.

As part of this evolution, the authors propose a novel concept: a contract between private businesses and the government not only for the extraction of hydrocarbons but also for producing high-value-added products derived from these resources. These could include refined petroleum products, petrochemicals, and liquefied natural gas (LNG). This framework envisions the joint creation of assets to add value to hydrocarbons, with subsequent income from the sale of high-value products shared between the parties. The authors term this model a value-added production-sharing contract (VAPSC).

Production-sharing contracts have evolved over several decades, with their key parameters undergoing significant changes. For instance, Indonesia’s PSC framework has seen 5–6 distinct contract generations. The specific parameter values depend on the country’s socio-economic conditions and institutional development level.

Modern PSC terms are shaped by improved hydrocarbon reserve assessments, technological advancements, access to financing, and other factors. For example, Gross Split Sharing contracts eliminate cost recovery for investors, transferring all risks to them. Price risks can be mitigated through Offtake Agreements, which offer stability for both producers and buyers. For producers, these agreements reduce exposure to market volatility by fixing prices and volumes, enabling more accurate financial planning. Buyers, in turn, secure a stable supply—often at more favorable terms than those available on the volatile open market.

The authors argue that future PSC development may involve greater contractual complexity, incorporating provisions for later stages of value creation. Additional production of new products could enhance project economics, maximize profits, and improve sector sustainability by generating value-added effects and engaging more stakeholders. The proposed VAPSC model aims to amplify added value, increase government and contractor revenues, expand export opportunities, and foster greater diversification and competence in the oil and gas sector.

The study focuses on Lebanon’s oil and gas sector, particularly the hydrocarbon prospective resources in the Levantine Basin, located in the eastern part of the Mediterranean Sea. Lebanon faces significant challenges, including a lack of experience, technical expertise, and financial resources required for such capital-intensive projects. Lebanon’s economy has struggled for decades, relying heavily on energy imports [1] and currently facing a severe economic crisis. With a public debt exceeding USD 45.57 billion [2] and a GDP of USD 17.94 billion [3], the country’s debt-to-GDP ratio stands at a staggering 254%.

The most promising production site is located in Block 9, where geologists predict significant natural gas reserves [4]. This study explores the structure of a potential agreement between the Lebanese government and private investors. A private oil and gas company would enter into a PSC with the government to produce natural gas in Block 9 and share the profits as per the agreed terms.

Lebanon seeks to develop its oil and gas sector, create jobs, and increase tax revenues. This can be achieved through the development of a PSC and its transformation into a VAPSC. This assumes that a private oil and gas company would produce natural gas in Block 9 (first building a platform and drilling wells), and the proceeds from the potential sales would be distributed between the government and the oil and gas company in accordance with one of the PSC types. To maximize value, the gas extracted from Block 9 would not be sold as raw natural gas but, instead, liquefied at a newly constructed LNG plant.

The government’s participation in the income generated by the LNG plant would be proportional to its share of investments in the plant’s construction. However, given Lebanon’s financial constraints, the government could secure its share in the project by foregoing immediate cash receipts under the PSC in favor of the private investor. The government would sell its share of natural gas at market prices, including to the LNG plant, but would reallocate the proceeds to fund its participation in the plant’s construction.

The study purports to substantiate and develop economic-mathematical modeling of VAPSC parameters as a new form of contracts for establishing and developing Lebanon’s oil and gas sector.

The objectives include (i) justifying the expansion of traditional PSC-type contracts to VAPSC; (ii) determining the government’s optimal share in the LNG project and identifying the optimal duration for which the state can waive immediate PSC revenues in favor of the contractor; (iii) establishing the maximum deadline for commissioning the LNG plant, beyond which its operation would become economically unviable.

2. Literature Review

Contractual relations in the oil and gas sector are grounded in contract theory, which has evolved over the past century, starting with the foundational works of R. Coase [5], O. Williamson [6], M. Jensen [7], I. Macneil [8], J. Commons [9], and other institutional theorists [10,11]. Contractual relations are widely applied across various sectors of the economy, including the oil and gas industry, where they exhibit unique characteristics [12,13,14,15,16,17,18,19,20]. A central tenet of contract theory is the partial alignment or coordination of the objectives of the involved parties—the principal and the agent.

Achieving this alignment requires different mechanisms, often grounded in game theory. For instance, D. Nash’s work on non-zero-sum games [21] demonstrated that all participants in contractual interactions can achieve mutually beneficial outcomes, while failure is also possible. Similarly, R. Covey’s exploration of the win-win principle [22] outlines how stakeholders with shared interests can collaborate effectively to generate benefits for all parties involved. This principle has been further elaborated in several works, such as Frankl [23], Henderson [24], Thompson [25], Wang [26], Elazouni [27], and Zahn [28]. Parties involved do not get everything they want, but they can be reasonably certain of getting what they agreed to.

Win-win scenarios emphasize developing a set of mutually acceptable terms that underpin project requirements, constraints, and plans [29]; see Mintu-Wimsatt and Graham [30]; Zachariassen [31]; Keshavarz [32]; and Altarawneh [33]. These relationships aim to reduce costs, improve quality, increase efficiency, and create long-term value (Dyer and Singh [34]; Nyaga et al. [35]; Rinehart et al. [36]). Depending on the context and the coordination of economic agents’ actions, contracts can be classified as classical, neoclassical, or relational [37].

Classical contracts, prevalent in the 1920s and 1930s [38,39], were designed to anticipate and address a wide range of contingencies, minimizing disputes and claims. However, the dynamic nature of modern markets—with their inherent risks and volatility—has rendered such rigid contracts less practical. Neoclassical contracts, which incorporate third-party mediation to resolve disputes [39,40,41,42,43,44,45,46], are similar to classical ones. In response to the increasing complexity of external environments and higher risks, contracts have further evolved into flexible relational contracts [47].

The implementation of oil and gas projects—particularly in upstream and downstream segments within developing countries—is characterized by distinct challenges and limitations. S. Hassan et al. [44] identified several key features of international contracts in this domain.

First, oil and gas projects typically require significant capital investments and intricate organizational coordination, increasing the importance of risk identification, assessment, and management [48,49,50]. Relational contracts are especially suited for such contexts.

Second, there are numerous project risks [51,52,53,54,55,56,57,58], which can range from technical problems (e.g., drilling in complex geological formations) to geopolitical risks (e.g., changes in government regulations or political instability in the region) [59,60,61]. Insufficient exploration, offshore hydrocarbon production, and complex geological conditions make risks bigger [62,63,64]. In some cases, technological, geopolitical [65,66,67], environmental [68], managerial [69,70,71], social [72], and digital risks are added [73,74]. Being flexible in response to unforeseen events [75,76,77,78] by revising initial conditions allows for restoring balance between the government and the oil company [78,79,80].

Third, emerging business opportunities and the government’s desire to increase its share of revenues may lead to an agency conflict. The growth of revenues may be associated both with the terms of the contract (taxation and distribution of products between the government and the investor) and with the addition of value in the subsequent processing of hydrocarbons. For example, further processing of oil at oil refineries and petrochemical plants, processing and liquefaction of gas, construction and operation of pipeline infrastructure, etc. can improve the economic results of the project. Justification of the terms in these agreements, including the creation of incentives for the investor, will allow for benefits and effects for both parties. For example, the value addition achieved through downstream activities—such as refining, petrochemical production, gas liquefaction, and pipeline construction—can improve the economic outcomes of the project. Preparing contracts with well-designed incentives helps reconcile competing interests.

As a result of long-term research [14,81,82,83,84,85], a classification of contract systems in the oil and gas sector has been developed [83]. Petroleum fiscal systems were categorized into concessionary systems and contractual systems. The Contractual Systems, in turn, encompassed service contracts (risk service contracts and pure service contracts) and production-sharing contracts (PSCs).

Aghion [86] uses contract theory to assess the strengths and weaknesses of contractual forms and to explain their evolution. Under concessionary systems, companies undertake exploration activities, acquire ownership of the production, and pay royalties to the host state. These agreements typically grant exclusive rights to explore and develop resources, alongside ownership of associated infrastructure [87]. Concessions are widely used in countries such as Kuwait, Sudan, Angola, Ecuador, and Norway [88].

Contractual systems include service contracts and production-sharing agreements. The fundamental difference of these systems is the partial cession of government rights and the granting of economic freedom to producers [43,89,90,91].

Service contracts are signed at the exploration and exploitation stages, while the government provides capital and technological know-how. The government has greater control over resource exploration and exploitation. The company does not have a share in the revenue received but receives a fee for providing the service; see Michael Likosky [92]. Depending on the distribution of exploration risks between the parties, a distinction is made between pure service contracts, where the government bears responsibility, and risk service contracts, where the company assumes risks [93,94]. The service contract is used in many countries such as Venezuela, Kuwait, Iraq, Bolivia, Ecuador, Turkmenistan, Iran, and Mexico [95].

PSCs allow oil companies to share production revenues with the host state. The government usually owns the equipment, while the companies manage field development; see Jenik Radon [81]. Johnston [83] examined the contractual elements of PSCs in detail and identified their key elements. A PSC as a contractual form should provide the government with an uncontested right to control the agent’s conduct [96] and the agent’s freedom to carry out any actions under the control of the principal [97]. Therefore, the contract should define the specific rights and obligations of the parties, the terms of their interaction and coordination, and the transfer of payments from the agent to the principal [98,99,100,101,102,103,104,105].

PSCs are commonly employed in Peru, Malaysia, Malta, Guatemala, Libya, Egypt, Syria, Jordan, Angola, China, Qatar, Gabon, Bangladesh, and the Philippines [106]. Numerous studies have examined the risks associated with production-sharing agreements. For instance, Pongsiri [84] concluded that PSCs effectively balance the high capital costs and uncertainties of oil and gas projects by mitigating moral hazard and adverse selection.

Hassan [107] argued that the structure of PSCs between national oil companies (NOCs) and international oil companies (IOCs) is critical for managing the risks and costs associated with petroleum exploration and development. Candeias [108] highlighted that various contract models, including joint ventures, licenses, concession agreements, and PSCs, are essential for risk management and resource allocation between states and oil companies.

The basic structure of the concession system comprises three key components: royalties, tax deductions, and taxes. Royalties are payments made by the licensee to the government as a percentage of gross revenue before any deductions (Echendu and Iledare [109]; Kasriel and Wood [110]; Ogolo and Nzerem [111]); ownership of the hydrocarbons is typically transferred to the contractor at the wellhead (Boykett et al. [112]). After royalties are paid, PSCs allocate a portion of the produced oil, known as cost oil, to the contractor to recover all capital and operating expenses incurred during the project’s various stages. Royalties and tax rates can either be fixed by regulation or negotiated with oil and gas companies (Johnston [83]; Kasriel and Wood [110]). The revenue remaining after deducting royalties and cost recovery is termed profit oil, which is divided between the government and investors according to the terms specified in the PSC (Echendu et al. [113]).

PSCs implement diverse fiscal policy approaches for hydrocarbon resource extraction, balancing cost recovery and profit-sharing mechanisms between the government and oil companies (Johnston [83], Nakhle [114], Echendu et al. [113]; Iledare [115]).

Indonesia has experienced a significant evolution in PSC models [43,116], with five distinct generations of contracts developed over time based on cost-sharing mechanisms. These contracts modify the share distribution between the government and investors, reducing investor risk through guaranteed cost reimbursement. However, for highly profitable fields, the government ensures a sufficient share of revenue.

Recently, low-margin field development has prompted a shift toward PSCs based on total income-sharing. Under this model (Gross Split Sharing), contractors bear the primary risks, and costs are not reimbursed. Instead, the government incentivizes contractors to adopt innovative technological solutions, reduce costs, and improve economic efficiency. This approach aligns the interests of both parties, ensuring project viability while minimizing financial exposure for the state.

In Lebanon, the potential adoption of Gross Split Sharing for future oil and gas contracts on the continental shelf is influenced by several key factors. These include the challenges of forecasting revenue from hydrocarbon field development due to price volatility and the risk of reserve non-confirmation resulting from insufficient exploration. Additionally, the possible low profitability of field development, Lebanon’s high public debt burden, and limited financing opportunities for hydrocarbon projects further shape the decision. Other challenges include the underdevelopment of exploration and production technologies, a shortage of skilled human resources for offshore operations, the absence of domestic oil and gas equipment production, and inadequate infrastructure. Furthermore, significant variations in the economic, geographical, and geological conditions of different fields (sections and blocks) impact their profitability. Given these factors, this study employs a research methodology based on the application of Gross Split Sharing to Lebanon’s offshore fields.

3. Methodology

This article tackles the challenge of defining VAPSC conditions between the state (Lebanon) and private businesses for the development of a hydrocarbon field. Simultaneously, it explores the construction and operation of a value-added asset—in this case, a liquefied natural gas (LNG) plant.

To implement the proposed concept, a research methodology has been developed, consisting of the following stages:

• Establishing PSC conditions, which involve defining the distribution of cash flows between the state and the contractor for hydrocarbon production.
• Establishing VAPSC conditions, including the terms for the state’s waiver of cash flows from hydrocarbon production in favor of the private partner, as well as the state’s share in investments for constructing the LNG plant.
• Establishing economic conditions, including a deadline for commissioning the LNG plant, beyond which its operation would no longer be economically viable.

3.1. Methodological Assumptions

An economic model based on the discounted cash flow (DCF) method has been developed to address these challenges. The model relies on the following assumptions:

• The selling prices of natural gas are assumed to remain constant throughout the project duration.
• Production and offtake of petroleum commodities start at t = 1, with a planning horizon of N. The construction and operation of the LNG plant are considered only within the interval from t = 0 to N, i.e., TL (final year of the LNG plant construction) ∈ [0; N], with cash flows from the LNG production and offtake generated between t = TL + 1 and N, i.e., FCF_LNG ∈ [TL + 1; N].
• Cash flows from LNG operations (FCF_LNG) are constant over the project’s implementation period, reflecting the plant’s maximum production capacity, which matches the plateau output of the associated hydrocarbon field. It is assumed that 100% of the gas is sold at market prices, with no sales allocated to the domestic market.
• Construction investments for the LNG plant may be spread over several years. For modeling purposes, all investments are discounted to t = 0 and aggregated. Therefore, there is a unified total present value of the investment, PVI_LNG.
• The state’s share (g) in financing the plant and its proportion of cash flows from LNG sales are assumed to be constant (g = const) throughout the project duration.

3.2. Government Cash Flows from Hydrocarbon Production According to the Gross Split Mechanism

Revenue from hydrocarbon product sales (in this study, natural gas) is distributed between the contractor and the government using the Gross Split mechanism (Figure 1).

The base split for natural gas allocates 52% to the government and 48% to the contractor. Additional percentage rates are applied to the Gross Split, including progressive and variable components for the contractor. Their values are set according to

Table A1. Additional contractor split formation. Adapted from [117].

№	Characteristic	Parameter	Additional Contractor Split
1	Field Status	POD I	5%
		POD II etc	3%
		No POD	0%
2	Field Location	Onshore	0%
		Offshore (0 < h ≤ 20 m)	8%
		Offshore (20 < h ≤ 50 m)	10%
		Offshore (50 < h ≤ 150 m)	12%
		Offshore (150 < h ≤ 1000 m)	14%
		Offshore (h > 1000 m)	16%
3	Reservoir Depth	≤2500 m	0%
		≥2500 m	1%
4	Supported Infrastructure	Well Developed	0%
		New Frontier Offshore	2%
		New Frontier Onshore	4%
5	Reservoir Condition	Conventional	0%
		Non-Conventional	16%
6	CO2 (%)	<5%	0%
		5% ≤ x < 10%	0.5%
		10% ≤ x < 20%	1%
		20% ≤ x < 40%	1.5%
		40% ≤ x < 60%	2%
		x ≥ 60%	4%
7	H2S (ppm)	<100	0%
		100 ≤ x < 1000	1%
		1000 ≤ x < 2000	2%
		2000 ≤ x < 3000	3%
		3000 ≤ x < 4000	4%
		x ≥ 4000	5%
8	Oil-Specific Gravity (API)	API < 25	1%
		API ≥ 25	0%
9	Local Content	<30	0%
		30 ≤ x < 50	2%
		50 ≤ x < 70	3%
		70 ≤ x < 100	4%
10	Production Phase	Primary	0%
		Secondary	6%
		Tertiary	10%
11	Cumulative Production (mmboe)	<30	10%
		30 ≤ x < 60	9%
		60 ≤ x < 90	8%
		90 ≤ x < 125	6%
		125 ≤ x < 175	4%
		x ≥ 175	0%
12	Oil Price	(85 − ICP) × 0.25	5%
13	Gas Price	<7	(7 − Gas Price) × 2.5
		7–10	0%
		>10	(10 − Gas Price) × 2.5

. The contractor’s total split is calculated as the sum of the Base, Variable, and Progressive splits.

The government’s annual cash flows under the PSC are calculated as:

FCF_t = Pr × Q_t × ((1 − GS) + TP × (GS − TC)),

(1)

where FCF_t is the government’s cash flow in year t, Pr is the selling price of natural gas, Qt is the hydrocarbon production volume in year t, GS is the contractor’s Gross Split rate, TP is the income tax rate, and TC is the total costs rate.

3.3. Discounting the Government’s Cash Flow from Hydrocarbon Production Under VAPSC

Depending on the projected production value, the equivalent annual cash flow for the government (FCF_g) is calculated. This subsection presents an explanation of its economic meaning and mathematical representation. FCF_g will be used in further modeling.

NPV can be found using the following formula:

$${\mathrm{N}\mathrm{P}\mathrm{V}}_{\mathrm{g}}={\sum }_{\mathrm{t}=1}^{\mathrm{N}}{\mathrm{FCF}}_{\mathrm{t}}\times {\displaystyle \frac{1}{{\left(1+\mathrm{r}\right)}^{\mathrm{t}}}},$$

(2)

where NPV_g is the net present value for the government, N is the project planning horizon, FCF_t is the government’s cash flow in year t, and r is the discount rate.

The cost of the project for the government depends on the annual flow rate (Formula (1)). Given the non-uniform hydrocarbon production—characterized by rising volumes in initial years, a plateau phase, and subsequent decline—the value of Q_t cannot be considered constant, i.e., Q_t ≠ const. Since the study relies on the concept of present value and discounting, the periods of production are very important from an economic point of view. The concept assumes that the earlier a unit of natural gas is produced, the more valuable it is in monetary terms.

Formulas (1) and (2) can be rewritten by pulling the value of the natural gas sales price and the government’s share outside the summation sign since they are assumed to be constant over time:

$${\mathrm{N}\mathrm{P}\mathrm{V}}_{\mathrm{g}}=\mathrm{P}\mathrm{r}\times ((1-\mathrm{G}\mathrm{S})+\mathrm{T}\mathrm{P}(\mathrm{G}\mathrm{S}-\mathrm{T}\mathrm{C}))\times {\sum }_{\mathrm{t}=1}^{\mathrm{N}}\left({\mathrm{Q}}_1\times {\displaystyle \frac{1}{{\left(1+\mathrm{r}\right)}^1}}+{\mathrm{Q}}_2\times {\displaystyle \frac{1}{{\left(1+\mathrm{r}\right)}^2}}+\dots +{\mathrm{Q}}_{\mathrm{N}}\times {\displaystyle \frac{1}{{\left(1+\mathrm{r}\right)}^{\mathrm{N}}}}\right).$$

(3)

For the sake of calculation flexibility, it is assumed that production Q_A is constant, i.e., Q_A = const.

This value is determined from the condition that the volume of Q_A should provide the same economic result (NPV_g) as the volumes of Q_t, at the same selling price and taking into account discounting. After applying Q_A, Formula (3) looks as follows:

$${\mathrm{NPV}}_{\mathrm{g}}=\mathrm{Pr} \times ((1-\mathrm{GS})+\mathrm{TP} \times (\mathrm{GS}-\mathrm{TC})) \times {\sum }_{\mathrm{t}=1}^{\mathrm{N}}\left({\mathrm{Q}}_{\mathrm{A}}\times {\displaystyle \frac{1}{{\left(1+\mathrm{r}\right)}^1}}+{\mathrm{Q}}_{\mathrm{A}}\times {\displaystyle \frac{1}{{\left(1+\mathrm{r}\right)}^2}}+\dots +{\mathrm{Q}}_{\mathrm{A}}\times {\displaystyle \frac{1}{{\left(1+\mathrm{r}\right)}^{\mathrm{N}}}}\right),$$

(4)

Since Q_A = const, it can be pulled outside the summation sign. Formula (4) can be rewritten:

$${\mathrm{NPV}}_{\mathrm{g}}=\mathrm{Pr} \times ((1-\mathrm{GS})+\mathrm{TP} \times (\mathrm{GS}-\mathrm{TC})) \times {\mathrm{Q}}_{\mathrm{A}} \times {\sum }_{\mathrm{t}=1}^{\mathrm{N}}\left({\displaystyle \frac{1}{{\left(1+\mathrm{r}\right)}^1}}+{\displaystyle \frac{1}{{\left(1+\mathrm{r}\right)}^2}}+\dots +{\displaystyle \frac{1}{{\left(1+\mathrm{r}\right)}^{\mathrm{N}}}}\right).$$

(5)

${\sum }_{\mathrm{t}=1}^{\mathrm{N}}\left({\displaystyle \frac{1}{{\left(1+\mathrm{r}\right)}^1}}+{\displaystyle \frac{1}{{\left(1+\mathrm{r}\right)}^2}}+\dots +{\displaystyle \frac{1}{{\left(1+\mathrm{r}\right)}^{\mathrm{N}}}}\right)$ in Formula (5) is the annuity-immediate coefficient and can be described as ${\displaystyle \frac{1-\frac{1}{{\left(1+\mathrm{r}\right)}^{\mathrm{N}}}}{\mathrm{r}}}$.

Then, Formula (5) can be rewritten:

$${\mathrm{NPV}}_{\mathrm{g}}=\mathrm{Pr} \times {\mathrm{Q}}_{\mathrm{A}} \times ((1-\mathrm{GS})+\mathrm{TP} \times (\mathrm{GS}-\mathrm{TC})) \times {\displaystyle \frac{1-\frac{1}{{\left(1+\mathrm{r}\right)}^{\mathrm{N}}}}{\mathrm{r}}}.$$

(6)

Having analyzed Formulas (2) and (6), we can conclude that the value Pr × Q_A × ((1 − GS) + TP × (GS − CR)) represents the cash flow FCF_g, which is constant over time and provides the same economic result (NPV_g) as the cash flows FCF_t.

The following value of FCF_g will be used in the study:

$${\mathrm{FCF}}_{\mathrm{g}}={\mathrm{NPV}}_{\mathrm{g}}/{\displaystyle \frac{1-\frac{1}{{\left(1+\mathrm{r}\right)}^{\mathrm{N}}}}{\mathrm{r}}}=\mathrm{Pr}\times {\mathrm{Q}}_{\mathrm{A}}\times ((1-\mathrm{GS})+\mathrm{TP}\times (\mathrm{GS}-\mathrm{TC}))=\mathrm{const}$$

(7)

By equating the right-hand sides of Formulas (3) and (6), we obtain the following expression:

$${\sum }_{\mathrm{t}=1}^{\mathrm{N}}\left({\mathrm{Q}}_1\times {\displaystyle \frac{1}{{\left(1+\mathrm{r}\right)}^1}}+{\mathrm{Q}}_2\times {\displaystyle \frac{1}{{\left(1+\mathrm{r}\right)}^2}}+\dots +{\mathrm{Q}}_{\mathrm{N}}\times {\displaystyle \frac{1}{{\left(1+\mathrm{r}\right)}^{\mathrm{N}}}}\right)={\mathrm{Q}}_{\mathrm{A}} \times {\displaystyle \frac{1-\frac{1}{{\left(1+\mathrm{r}\right)}^{\mathrm{N}}}}{\mathrm{r}}}.$$

(8)

Next, Q_A is calculated as follows:

$${\mathrm{Q}}_{\mathrm{A}}=\left({\sum }_{\mathrm{t}=1}^{\mathrm{N}}{\mathrm{Q}}_1\times {\displaystyle \frac{1}{{\left(1+\mathrm{r}\right)}^1}}+{\mathrm{Q}}_2\times {\displaystyle \frac{1}{{\left(1+\mathrm{r}\right)}^2}}+\dots +{\mathrm{Q}}_{\mathrm{N}}\times {\displaystyle \frac{1}{{\left(1+\mathrm{r}\right)}^{\mathrm{N}}}}\right)\times {\displaystyle \frac{\mathrm{r}}{1-\frac{1}{{\left(1+\mathrm{r}\right)}^{\mathrm{N}}}}}.$$

(9)

Q_A is proposed to be considered the annual average present volume of production. It signifies the estimated volume of annual production, which is constant over time, which provides the same economic result as the projected production rate.

3.4. Determining the Production Profile

Determining the production rate is necessary to find the forecast value of equivalent annual cash flows. The authors propose to use a mathematical model that is based on several parameters [118]:

$${\mathrm{Q}}_{\mathrm{t}}=\left\{\begin{array}{c}{\displaystyle \frac{{\mathrm{Q}}_{\max }}{\mathrm{yr}}}+{\mathrm{Q}}_{\mathrm{t}-1}, \mathrm{t}-{\mathrm{t}}_{\mathrm{s}} \le \mathrm{y}\mathrm{r};\\ {\mathrm{Q}}_{\max }, \mathrm{t}-{ \mathrm{t}}_{\mathrm{s}} > \mathrm{y}\mathrm{r} \text{и} {\displaystyle \frac{{\mathrm{W}}_{\mathrm{t}-1}}{\mathrm{W}}} \le \mathrm{P};\\ {\mathrm{Q}}_{\max } \times {\mathrm{e}}^{{-\mathsf{\alpha }}_{\mathrm{t}}}, {\displaystyle \frac{{\mathrm{W}}_{\mathrm{t}-1}}{\mathrm{W}}} > \mathrm{P};\\ 0, \mathrm{t} \in \left[0; {\mathrm{t}}_{\mathrm{s}}\right] \mathrm{или} {\mathrm{W}}_{\mathrm{t}-1} \ge \mathrm{W},\end{array}\right.$$

(10)

where Q_t is the production rate in year t, t ∈ [0; N]; t_s is the production start; W is the initial recoverable reserves; Q_max is the plateau production (10% of W); yr is the period to plateau production; P is the reserves recovered before the end of the plateau period; W_t−1 is the accumulated production before the beginning of period t; α_t is the decline rate in year t, α_t = Q_t−1/(W − W_t−1).

The resulting production rate Q_t is used in Formula (9).

3.5. Determining the Optimal Timeline for the Government to Waive Hydrocarbons’ Cash Flows

The government’s decision to waive future cash receipts from the development of Block No. 9 and subsequent gas production serves as an incentive for private partners to invest in the LNG plant. This incentive manifests as a reduction in the total payments due to the state under the PSC, with the private investor being exempted from payments for a specific period.

The cost of the LNG plant consists of two components: government investment and private partner investment. Applying discounting principles, the total investment is expressed as the sum of the present value of cash flows. State investment in the LNG plant is represented as the present value of its share of the cash flows, while the remaining costs are covered by the private business (the oil and gas company):

PVI_LNG = PVI_g + PVI_k,

(11)

where PVI_LNG is the present value of investments in the LNG plant; PVI_g is the present value of government investments; PVI_k is the present value of private investments.

PVI_g can be expressed as the product of the government’s share in the required investments (g) by the total present value of the LNG plant (PVI_g = g × PVI_LNG); as the share of the private business (k) can be represented as k = 1 − g, PVI_k = (1 − g) × PVI_LNG.

The present value of the government’s cash receipts is proportional to its share in the total investment value, given as follows:

$${\mathrm{PVI}}_{\mathrm{g}}={\mathrm{NPV}}_{\mathrm{g}}={\sum }_{\mathrm{t}=1}^{\mathrm{N}}{\mathrm{FCF}}_{\mathrm{g}}\times {\displaystyle \frac{1}{{\left(1+\mathrm{r}\right)}^{\mathrm{t}}}},$$

(12)

where NPV_g is the net present value of cash receipts the government forgoes from the development of Block No. 9; FCF_g is the equivalent annual cash flow of the government from the development of Block No. 9; T is the period during which the government waives cash receipts; t is the development period of Block No. 9; and r is the discount rate.

To ensure proportionality between investment shares and economic returns from the LNG plant, the following condition is introduced:

PVI_g/PVI_LNG = NPV_g/NPV_LNG,

(13)

where NPV_g is the net present value of the LNG project for the government; NPV_LNG is the net present value of the LNG project.

Formula (12) can be reformulated:

$$\mathrm{g}\times {\mathrm{PVI}}_{\mathrm{LNG}}={\mathrm{FCF}}_{\mathrm{g}} \times {\displaystyle \frac{1-\raisebox{1ex}{$1$}\!\left/ \!\raisebox{-1ex}{${\left(1+\mathrm{r}\right)}^{\mathrm{T}}$}\right.}{\mathrm{r}}}$$

(14)

Formula (14) can be used to find the recommended period for the government to waive cash receipts T depending on the government’s share (g) in the project to create an LNG plant with known (given) total investments (PVI_LNG), planning horizon (N), and annual cash receipts from field development (FCF_g):

$$\mathrm{T}={\log }_{(1+\mathrm{r})}\left({\displaystyle \frac{{\mathrm{FCF}}_{\mathrm{g}}}{{\mathrm{FCF}}_{\mathrm{g}}-\mathrm{r} \times \mathrm{g} \times { \mathrm{PVI}}_{\mathrm{LNG}}}}\right)$$

(15)

T can be calculated for each g. The state’s share in constructing the LNG plant (and its subsequent revenue) is thus a negotiated parameter between the private investor (or consortium) and the state.

This value determines the period during which the Lebanese government can forego future cash flows from Block No. 9 in favor of private partners.

Based on the calculations, two scenarios may arise:

• If 0 ≤ T ≤ N, the state’s cash flows from gas production and sales are sufficient to cover its contractual share of financing.
• If T ≥ N, the state’s cash flows are insufficient, requiring a reduction in its investment share and corresponding economic returns from the LNG plant.

3.6. Determining the Deadline for LNG Plant Construction

If the construction is completed later than the deadline, investments will not pay off by the N period, i.e., the operation of this plant will be economically inefficient. Therefore, the LNG plant should be built no later than a certain deadline. The deadline is determined further based on two conditions.

First, the NPV of the asset (LNG plant) must be non-negative (NPV_LNG ≥ 0), which indicates that the project profitability is not less than the discount rate (r,%).

The present values of FCF_LNG cash flows from LNG production and sales can be found as follows:

$${\mathrm{PV}}_{\mathrm{LNG}}={\sum }_{\mathrm{t}=\mathrm{TL}+1}^{\mathrm{N}}{\mathrm{FCF}}_{\mathrm{LNG}}\times {\displaystyle \frac{1}{{\left(1+\mathrm{r}\right)}^{\mathrm{t}}}},$$

(16)

where PV_LNG is the present value of cash flows FCF_LNG for the period from TL + 1 to N; TL is the final year of construction and investment.

Secondly, the maximum duration for which the LNG plant can generate cash flows FCF_LNG is from t = 1 to t = N, since we need at least one period (t = 0) in which investments are fulfilled (TL = 0).

In this case, the present value of cash flows from the LNG plant for the desired period (FCF_LNG) is determined by the following expression:

$${\mathrm{PV}}_{\mathrm{NLNG}}={\sum }_{\mathrm{t}=1}^{\mathrm{N}}{\mathrm{FCF}}_{\mathrm{LNG}}\times {\displaystyle \frac{1}{{\left(1+\mathrm{r}\right)}^{\mathrm{t}}}}={\mathrm{FCF}}_{\mathrm{LNG}} \times {\displaystyle \frac{1-\raisebox{1ex}{$1$}\!\left/ \!\raisebox{-1ex}{${\left(1+\mathrm{r}\right)}^{\mathrm{N}}$}\right.}{\mathrm{r}}},$$

(17)

where PV_NLNG is the present value of cash flows FCF_LNG from t = 1 to t = N; N is the planning horizon.

It should be noted that investments in the construction of the LNG plant can be made and completed during the entire period of field development, for example, not in the zero period, but in the first one (TL = 1). In this case, the asset will begin to generate cash flows FCF_LNG only from the second period (t = 2). That is, the present value of cash flows from the LNG plant will decrease by the amount: ${\sum }_{\mathrm{t}=1}^{\mathrm{TL}}{\mathrm{FCF}}_{\mathrm{LNG}}\times {\displaystyle \frac{1}{{\left(1+\mathrm{r}\right)}^{\mathrm{t}}}}$ = FCF_LNG × ${\displaystyle \frac{1-\raisebox{1ex}{$1$}\!\left/ \!\raisebox{-1ex}{${\left(1+\mathrm{r}\right)}^{\mathrm{TL}}$}\right.}{\mathrm{r}}}$.

Consequently:

$${\mathrm{PV}}_{\mathrm{LNG}}={\sum }_{\mathrm{t}=\mathrm{TL}+1}^{\mathrm{N}}{\mathrm{FCF}}_{\mathrm{LNG}}\times {\displaystyle \frac{1}{{\left(1+\mathrm{r}\right)}^{\mathrm{t}}}}={\mathrm{PV}}_{\mathrm{NLNG}}-{\mathrm{FCF}}_{\mathrm{LNG}} \times {\displaystyle \frac{1-\raisebox{1ex}{$1$}\!\left/ \!\raisebox{-1ex}{${\left(1+\mathrm{r}\right)}^{\mathrm{TL}}$}\right.}{\mathrm{r}}}={\mathrm{FCF}}_{\mathrm{LNG}} \times {\displaystyle \frac{1-\raisebox{1ex}{$1$}\!\left/ \!\raisebox{-1ex}{${\left(1+\mathrm{r}\right)}^{\mathrm{N}}$}\right.}{\mathrm{r}}}-{\mathrm{FCF}}_{\mathrm{LNG}} \times {\displaystyle \frac{1-\raisebox{1ex}{$1$}\!\left/ \!\raisebox{-1ex}{${\left(1+\mathrm{r}\right)}^{\mathrm{TL}}$}\right.}{\mathrm{r}}},$$

(18)

where PV_LNG is the present value of cash flows FCF_LNG from TL to N; TL is the year of construction and investment.

Taking into account the condition NPV_LNG ≥ 0, the condition of economic efficiency is expressed as follows:

$$\begin{gathered} {\mathrm{NPV}}_{\mathrm{LNG}}={\mathrm{PV}}_{\mathrm{LNG}}-{\mathrm{PVI}}_{\mathrm{LNG}}\ge 0, \\ {\mathrm{PV}}_{\mathrm{LNG}}\ge {\mathrm{PVI}}_{\mathrm{LNG}}, \\ {\mathrm{FCF}}_{\mathrm{LNG}} \times {\displaystyle \frac{1-\raisebox{1ex}{$1$}\!\left/ \!\raisebox{-1ex}{${\left(1+\mathrm{r}\right)}^{\mathrm{N}}$}\right.}{\mathrm{r}}}-{\mathrm{FCF}}_{\mathrm{LNG}} \times {\displaystyle \frac{1-\raisebox{1ex}{$1$}\!\left/ \!\raisebox{-1ex}{${\left(1+\mathrm{r}\right)}^{\mathrm{TL}}$}\right.}{\mathrm{r}}}\ge {\mathrm{PVI}}_{\mathrm{LNG}}, \end{gathered}$$

(19)

where NPV_LNG is the net present value of the project for the construction and operation of the LNG plant; PV_LNG is the present value of cash flows FCF_LNG for the desired period; PVI_LNG is the present value of the required investments for the construction of the LNG plant; N is the planning horizon; TL is the year of construction and investment.

Therefore, the desired deadline for completing the construction of the LNG plant (after which the operation of this plant becomes economically inefficient) can be determined by rewriting Formula (18):

$$\begin{gathered} {\displaystyle \frac{{\mathrm{PVI}}_{\mathrm{LNG}} \times \mathrm{r}}{{\mathrm{FCF}}_{\mathrm{LNG}}}} \le {\left(1+\mathrm{r}\right)}^{-\mathrm{TL}}{-\left(1+\mathrm{r}\right)}^{-\mathrm{N}}, \\ \mathrm{TL} \le -{\log }_{(1+\mathrm{r})}\left({\displaystyle \frac{{\mathrm{PVI}}_{\mathrm{LNG}} \times \mathrm{r}}{{\mathrm{FCF}}_{\mathrm{LNG}}}}+ {\left(1+\mathrm{r}\right)}^{-\mathrm{N}}\right) \end{gathered}$$

(20)

It should be noted that the following situations are possible:

• The resulting deadline has a value of N ≥ TL ≥ 0; hence, the asset must be commissioned no later than the year TL, i.e., revenue generation and the subsequent generation of positive cash flows must begin no later than TL + 1.
• The resulting deadline has a value of TL < 0, which means that in the zero period (t = 0) the asset must already be in operation and generate positive cash flows in order to maintain economic efficiency; i.e., by the beginning of the period (from t = 0 to t = N) the plant must already be in operation to be economically efficient. This result, TL < 0, indicates that the economic efficiency of the project is impossible under the given conditions.

Figure 2 summarizes the results of the methodology.

4. Methods and Data

To apply the proposed methodology, it is essential to consider Lebanon’s current economic, geological, and tax conditions. Since the study focuses on developing a hydrocarbon field in the Levantine Basin, it is necessary to estimate the potential reserves. A probabilistic resource assessment of the entire basin, covering an area of 83,000 km², indicates gas volumes of 50.087 (P95), 112.613 (P50), and 227.43 (P5) trillion cubic feet (equivalent to 1418.3 (P95), 3188.84 (P50), and 6440.1 (P5) billion m³) [119]. This paper examines the prospects for industrial gas production on the Lebanese shelf, specifically in Block No. 9, which is part of the Levantine Basin and covers an area of 1742 km² [120].

Since the study focuses on Block No. 9, we propose interpolating the estimated gas volumes for the entire basin in proportion to the block’s area. Accordingly, the estimated initial recoverable reserves for Block No. 9 are 29.77 (P95), 66.93 (P50), and 135.16 (P5) billion m³ of natural gas.

The study considers a time frame from 2030 to 2050. Based on an analysis of documents [121], we assume that if industrial-scale hydrocarbon reserves are confirmed in Block No. 9, production will commence by 2030 to meet Lebanon’s economic needs. The planning horizon extends to 2050, with the reference point t = 0 corresponding to 2030 and N = 20 corresponding to 2050.

The next step involves determining the parameters of the PSC to establish the Total Split value for private businesses (GS). The GS value is derived from Table A1, while the Additional Contractor Split is based on information presented in the manuscript [121]. The analysis results, summarized in

Table 1. Total contractor split formation.

№	Characteristic	Parameter	Additional Contractor Split
1	Field Status	POD I	5%
2	Field Location	Offshore (h > 1000 m)	16%
3	Reservoir Depth	≥2500 m	1%
4	Supported Infrastructure	New Frontier Offshore	2%
5	Reservoir Condition	Conventional	0%
6	CO2 (%)	<5%	0%
7	H2S (ppm)	x ≥ 4000	5%
8	Oil Specific Gravity (API)	API ≥ 25	0%
9	Local Content	50 ≤ x < 70	3%
10	Production Phase	Primary	0%
11	Cumulative Production (mmboe)	x ≥ 175	0%
12	Oil Price	–	–
13	Gas Price	<7	(7 − 3.5) × 2.5 = 8.75%
14	Additional Contractor Split	40.75%
15	Base Contractor Split	48%
16	Total Contractor Split	88.75%

, indicate that the total split for private businesses (GS) is 88.75%, with total costs set at 60%.

The next step is to determine the prices for natural gas (USD/1000 m³) and LNG. The assumed price for natural gas is 3.5 USD/MMBTU or 123.83 USD/1000 m³. The assumed price for LNG, based on January 2024 levels, is 14.34 USD/MMBTU (or 682.86 USD/t) [122].

Lebanon’s income tax rate is set at 34%, and the discount rate is established at 10%.

5. Results

5.1. Determination of the Economic Effect of Hydrocarbon Deposit Development for the Government (Basic PSC, Production and Sale of Natural Gas)

The gas production profiles for each reserve distribution estimate in Block No. 9 were determined using the system of equations (Equation (10)).

Table 2. The initial data and expected technological parameters.

Indicators	P95	P50	P5
Initial recoverable reserves (W), billion m3	29.77	66.93	135.16
Proportion of recoverable reserves produced before the end of the plateau (P),%	70	70	70
Maximum hydrocarbon production rate (Qmax), billion m3	2.977	6.693	13.516
Start of hydrocarbon production (ts)	1 (2031)	1 (2031)	1 (2031)
Timepoint to reach maximum production (yr)	3 (2033)	3 (2033)	3 (2033)

presents the initial data and expected technological parameters for field development.

The estimated annual production volumes (production profiles) are presented in Appendix A, with a graphical representation provided in Figure 3.

After calculating the gas production profiles, the economic efficiency parameters of the field development project under the PSC for the government were determined using formulas (9, 6, and 7). The present value of cash receipts from the production and sale of hydrocarbons from Block No. 9 (NPV_g) and the government’s equivalent annual cash flow from the sale of products from Block No. 9 (FCF_g) were determined for three resources’ estimates (P5, P50, and P95). According to the methodology, formulas (9, 6, and 7) should be applied sequentially. The calculation results are presented in

Table 3. The economic efficiency parameters of the field development project for the government.

Parameter	P5	P50	P95
NPVg, million USD	1883.8	934.9	415.4
FCFg, million USD/year	221.3	109.8	48.8

.

5.2. Economic Indicators of an LNG Plant at Different Production Capacities

The analysis assumes a constant production capacity for the LNG plant, which corresponds to the plateau production level, i.e., the maximum annual production rate from the considered deposit. Three different maximum annual production volumes, corresponding to the three geological estimates, determine the three plant capacity variants.

The annual volumes of natural gas production are converted into an equivalent mass of LNG. For example, under the P50 assessment scenario, 6.693 billion m³ of natural gas, after liquefaction, equates to approximately 4.86 million tons of LNG. Consequently, the designed annual capacity of the LNG plant for the P50 estimate is 4.86 million tons per year. Capital costs for plant construction are estimated using the analogy method. The present value of the required investment for the construction of the LNG plant, PVI_LNG, is determined based on publicly available data [123] and inflation forecasts until 2030.

According to our estimates, the compounded costs by 2030, adjusted for inflation, will amount to approximately USD 6.79 billion (PVI_LNG = USD 6.79 billion). The results for other scenarios are presented in

Table 4. Economic indicators of an LNG plant.

Indicators	P5	P50	P95
Maximum production rate, billion m3/year	13.516	6.693	2.977
LNG plant capacity, million tons/year	9.78	4.86	2.16
CapEx (PVILNG), billion USD	23	6.79	3.06
OpEx, billion USD/year	2.13	0.97	0.43
Depreciation (DA), billion USD/year	1.15	0.34	0.15
Annual cash receipts from LNG plant operations (FCFLNG), million USD	3393	1666	740.5

.

The FCF_LNG value, representing cash receipts and payments from production at the LNG plant, remains constant over the operational years. In accordance with the methodology, it is determined by the formula:

FCF_LNG = (Q_LNG × Pr_LNG − OpEx − DA) × (1 − T) + DA,

(21)

where Q_LNG is the plant’s capacity, t/yr; Pr_LNG is the price per ton of LNG, USD/t; OpEx is the operating costs, assumed to be equal to 2% of the capital costs (PVI_LNG) plus the cost of natural gas liquefied (Q_max × Pr) [123], USD/yr; T is the income tax rate; DA is depreciation deductions, USD/year, determined as DA = PVI_LNG/N, where N is the planning horizon (20 years in this study). The values of FCF_LNG for three estimations, the initial data, and the results are shown in Table 4.

5.3. Determination of the Optimal Period for the Government to Forego Payments Under the PSC and Its Share in LNG Plant Financing

Formula (15) is used to determine the recommended period for the government to renounce cash inflows (T) under the basic PSC, depending on the government’s share (g) in financing the LNG plant and the anticipated economic benefits. This calculation considers total investment (PVI_LNG), the planning horizon (N), and equivalent annual cash receipts from field development (FCF_g).

The recommended period for the government to forego cash receipts from natural gas production and sales in Block No. 9 has been calculated for each of the three geological estimates (P5, P50, and P95) under different levels of government investment in the LNG plant, ranging from 0% to 100%. The input parameters for Formula (15) include FCF_g (Table 3), PVI_LNG (

Table 5. The optimal period for the government to forego payments and its share in LNG plant financing.

g	1%	2%	3%	4%	5%	6%	7%	8%	9%	10%	11%	12%	13%	14%	15%	16%	…	100%
P5	1.2	2.4	3.9	5.6	7.7	10.3	13.6	18.7	28.7	∝	∝	∝	∝	∝	∝	∝	∝	∝
P50	0.67	1.38	2.15	2.98	3.88	4.86	5.9	7.2	8.5	10.1	12.0	14.2	17.1	21.1	27.5	47.6	∝	∝
P95	0.68	1.41	2.19	3.03	3.95	4.95	6.1	7.3	8.7	10.3	12.3	14.6	17.7	22.0	29.6	∝	∝	∝

), and r = 10%. The results are presented in Table 5.

The results (Table 5) can be interpreted as follows. If the government contributes 5% to the LNG plant’s financing under the P95 valuation, it should forego cash receipts under the basic PSC for approximately four years (from 2031 to 2034 inclusive).

5.4. Determining the Deadline for Completion of the LNG Plant Construction

To align with the study’s objectives, the deadline for completing the construction of the LNG plant (TL) is determined. The plant begins operations and generates revenue in year TL + 1. The deadline for completing construction is calculated using Formula 20 for each resources estimate (P5, P50, P95), with PVI_LNG values taken from Table 5 and FCF_LNG values determined via Formula (21). The planning horizon (N) is set at 20 years, extending until 2050.

The calculated deadlines (TL) for each estimate are presented in Table 6:

• TL_P5 ≤ 2,
• TL_P50 ≤ 6.16,
• TL_P95 ≤ 6.05.

Table 6. The calculated deadlines for each magnitude of potential resources.

	Deadline for LNG Plant Completion, TL (Years)	Interpretation
P5	2.00	Completion in 2032 (or earlier), full capacity achieved by 2033
P50	6.16	Completion in the first half of 2037, operation begins mid-2037
P95	6.05	Completion in early 2037, operation starts early/mid-2037

Table 6. The calculated deadlines for each magnitude of potential resources.

	Deadline for LNG Plant Completion, TL (Years)	Interpretation
P5	2.00	Completion in 2032 (or earlier), full capacity achieved by 2033
P50	6.16	Completion in the first half of 2037, operation begins mid-2037
P95	6.05	Completion in early 2037, operation starts early/mid-2037

The values presented in Table 6 require further clarification. In the case of option P5, the construction deadline is set at a maximum of two years. This implies that the LNG plant must be completed by 2032 (or earlier) and must achieve full operational capacity by 2033. Failure to meet this timeline would render the construction and operation of the LNG plant economically unviable.

Figure 4 presents the results of the VAPSC-type agreement under the conditions of natural gas production at Block 9 and the construction of an LNG plant in the territory of the State of Lebanon.

6. Discussion

Based on an analysis of the literature and international experience in oil and gas contracting, we have identified the key characteristics of relational contracts in the oil and gas sector that underpin PSCs in Lebanon. These characteristics include government dominance in shaping the oil and gas sector, which is facilitated through industrial policy mechanisms and PSCs; long-term contracts (typically 20 years); profitability and risk distribution through economic modeling mechanisms, ensuring a balance of interests between stakeholders; complexity of contracts related to value creation, including oil and gas processing, LNG production, and infrastructure development; and the impact of various risks, including price volatility, technological challenges, and investment uncertainties.

These contract characteristics are extensively supported by research in the field. For example, as noted in the paper [117], relational contracts across different sectors share common features such as a high degree of flexibility and repeated transactions over an extended period, broad future opportunities, the critical role of personal relationships in fostering collaboration, as well as anti-presentation and anti-discreteness.

Researchers highlight [124,125,126] several conditions that favor the use of relational contracts. In the context of the oil and gas industry, we have identified the following key conditions:

• Long-term collaboration and trust-building, which ensure sustained commitment from both parties and enhance future business opportunities.
• Fairness and good faith, fostering stability, reducing disputes, and maintaining a balance of interests.
• Compatibility with complex, long-term projects, enabling contract evolution and continued alignment of interests over time, with a focus on stability rather than short-term gains.
• Adaptability to global trends, including technological advancements, geopolitical shifts, economic fluctuations, and innovation-driven developments.
• Flexibility in response to changing conditions, ensuring contracts remain relevant and equitable, thereby minimizing conflicts or premature terminations in the face of unexpected challenges.

We propose a more detailed discussion of the contractual parameters for Lebanon while considering the assumptions underlying this study. A comparison of contract structure, investment, and revenue-sharing arrangements is presented in

Table 7. Comparison of contract structures [66,127].

Model	Contract Structure	Government Participation/Control	Mechanism for Investment and Profit-Sharing
Cost-recovery PSC (pre-1984)	The contractor funds 100% of exploration and development risk. Cost recovery is capped at 40% of annual gross revenue; remaining production becomes “equity oil/gas”. 20% First-Tranche Petroleum (FTP) is taken before cost recovery. Typical term ≈ 30 yrs (6 yrs exploration + 24 yrs exploitation).	The state owns hydrocarbons and all imported equipment; custody passes to the contractor only during operations. Pertamina/BP Migas (now SKK Migas) approves annual work programmes, budgets, and manpower.	The allowable costs, inventories, and depreciation are recovered within the 40% cap. Investment credit of 17–55% of approved development CAPEX accelerates payout. After cost recovery + FTP: after-tax split = 85% gov./15% contractor for oil; 70%/30% for gas.
Gross Split PSC	No cost recovery; production is split on gross output. Base split: oil 57% gov./43% contractor; gas 52%/48%. The split is then adjusted by the agreed variable (field depth, frontier, CO2, infra, etc.) and progressive factors (price, cumulative output).	The state retains resource ownership; SKK Migas’ role is limited to approving/monitoring the Work Programme (WP) rather than budgets.	Contractor’s take = Base split ± variable ± progressive adjustments; the contractor pays income tax out of its share. Government take = production share + bonuses + contractor corporate income tax (CIT).

.

As previously mentioned, the government’s participation share (g) in financing the construction of the LNG plant and its corresponding share of the profits is presented as an economic parameter (a contractual value) in the agreement between the private investor and the government. The value of g directly determines the period for which the government agrees to forego revenue from natural gas sales during field development.

To optimize the participation share and its corresponding deferral period, we propose a model that calculates optimal participation share/term pairs. The government must determine and approve the most suitable pair for the VAPSC based on project risks and macroeconomic conditions. Key risk factors include revenue risks associated with fluctuations in natural gas and LNG prices and the potential non-confirmation of reserves due to limited geological data; profitability risks associated with the possibility of lower-than-expected returns from field development; market risks associated with uncertainty surrounding LNG sales and potential alternative export routes in collaboration with Mediterranean countries; and macroeconomic risks, which include political and economic instability in Lebanon, high public debt burden and inflationary pressures, and limited national financing capacity for hydrocarbon projects.

In Table 5, values in bold italics indicate that the required revenue deferral period exceeds the project’s planning horizon (N = 20 years) for Block No. 9. This means that even if the government fully relinquishes its PSC cash flows for 20 years in favor of private investors, the accumulated funds would still be insufficient to cover the contractual government share. Consequently, the government must reduce its share of financing, which will, in turn, decrease its share of future profits and the overall economic impact of the LNG plant’s operations. For example, under the P50 scenario, the maximum feasible government share in the LNG plant is 13%. A 14% share would exceed the available financial resources within the 20-year horizon.

The ∝ symbol indicates scenarios where even an indefinite deferral of PSC revenues would be insufficient to support the declared government share g.

Thus, the negotiable government participation share ranges are as follows: 0–8% (P5), 0–13% (P50), and 0–13% (P95).

The estimated timelines for LNG plant construction fall within the planning horizon (N = 20 years), specifically N (20) ≥ TL ≥ 0 (Table 6). The shortest construction period corresponds to the P5 scenario, which requires a plant with a 9.78 million tons/year capacity to be completed by 2032. For P50 (4.86 million tons/year) and P95 (2.16 million tons/year), the construction deadlines are nearly identical, with completion expected in the first half of 2037. The P5 scenario requires significantly higher capital investment (USD 23 billion, Table 4), which may explain the shorter construction period.

Assuming indefinite operation (t → ∝), the economic effect of the LNG plant is calculated using the present value (PV) formula: PV_LNG = FCF_LNG/r − PVI_LNG (infinite annuity). Under the three scenarios, the PV_LNG values are USD 10.9 billion (P5), USD 9.8 billion (P50), and USD 4.35 billion (P95).

The equivalent annual government cash flows from profit tax (FCF_TP) under each geological estimate are USD 1.16 billion (P5), USD 0.68 billion (P50), and USD 0.3 billion (P95).

The present value of profit tax receipts, assuming perpetual LNG plant operation (t → ∝, PV_TP = FCF_TP/r), is USD 11.6 billion (P5), USD 6.8 billion (P50), and USD 3 billion (P95).

If the study’s assumptions change, the economic parameters of the contracts will also be affected. For example, a projected 25% increase in global LNG demand by 2050 could positively impact project indicators, while a policy mandating greater domestic gas consumption and reduced investor returns could negatively affect profitability.

Several limitations in this study could be addressed in future research.

First, the methodology is based on a Discounted Cash Flow (DCF) model, which does not account for financing risks, hydrocarbon price volatility, political instability, or technological challenges related to offshore gas production. While the study incorporates probabilistic assessments of hydrocarbon reserves to account for geological uncertainty, a broader risk analysis could significantly alter cash flow distributions among stakeholders.

Second, the study assumes that all produced LNG will be sold at market prices, but it does not analyze global LNG demand, logistics chains, or potential Mediterranean buyers. No evaluation was conducted regarding domestic gas sales in Lebanon, either within the PSC framework or under the LNG plant construction scenario.

By addressing these limitations, further research could refine the economic modeling approach, improve risk valuation, and provide a more comprehensive framework for optimizing government hydrocarbon sector strategy.

7. Conclusions

This study identifies the key characteristics of relational contracts in the oil and gas sector, which form the basis for production-sharing contracts (PSCs) in Lebanon. These characteristics include government dominance in shaping the oil and gas sector, facilitated through industrial policy mechanisms and PSCs; long-term contracts (typically 20 years); profitability and risk distribution through economic modeling mechanisms, ensuring a balance of interests between stakeholders; the complexity of contracts related to value creation, including oil and gas processing, LNG production, and infrastructure development; and the impact of various risks, such as price volatility, technological challenges, and investment uncertainties.

This paper presents a methodological approach for defining VAPSC contractual terms within Lebanon’s institutional framework, specifically for extracting natural gas from the Mediterranean shelf and liquefying and marketing LNG in global markets. By allowing for greater supply flexibility, this model enhances both the competitiveness and profitability of LNG projects.

The study focuses on the following key objectives: determining the government’s optimal share in the LNG project and identifying the optimal duration for which the government can waive immediate cash receipts in favor of the contractor; and establishing the maximum deadline for commissioning the LNG plant, beyond which its operation would become economically unviable.

The proposed methodological framework comprises two stages: 1) initial product distribution based on the terms of the Gross Split Sharing contract; 2) sharing the resulting economic benefits between the government and private investors in proportion to their financial contributions to hydrocarbon production capacity, field development, and LNG plant construction.

The primary contributions and scientific innovations of this study include the following:

• A new type of VAPSC agreement has been proposed, focusing on joint production and sharing of high-value-added products. Specifically, hydrocarbons or minerals extracted under the terms of the contract are processed to manufacture new products, which are then shared between the state and the contractor.
• An economic and mathematical model has been developed to determine the government’s optimal share in the joint LNG plant project, as well as the optimal duration for which the state can waive immediate PSC revenues in favor of the contractor under the VAPSC framework.
• Additionally, an economic and mathematical model has been developed to determine the maximum deadline for commissioning the LNG plant, beyond which its operation would become economically unviable under the VAPSC framework.
• A methodological approach, based on the proposed economic and mathematical models, has been validated in the Lebanese context. This approach was applied to the example of offshore gas production (Block No. 9), the construction and operation of an LNG plant, and the subsequent sharing of manufactured products between the state and the contractor. The VAPSC terms were analyzed considering the geological assessment of P5, P50, and P95 potential resources of Block No. 9.

The primary limitation of this study lies in its reliance on economic modeling based on publicly available data concerning costs, prices, and expected production volumes. These calculations incorporate geological risks as well as economic and tax conditions specific to Lebanon. However, the study does not include an analysis of market conditions, competition, or scenario-based assessments under different economic and geopolitical circumstances.

Future research should focus on conducting a comprehensive analysis and forecast of natural gas and LNG markets, logistics and supply chain flows, competitive dynamics, and their impact on contract structuring and additional market factors.

The proposed economic modeling approach for PSCs can be adapted to other integrated contracts involving both hydrocarbon extraction and processing. Beyond LNG production, potential applications include hydrocarbon transportation, oil refining, and petrochemicals.